Dividends
Devon pays a quarterly dividend which can be comprised of a fixed dividend and a variable dividend. The variable dividend is dependent on quarterly cash flows, among other factors. The following table summarizes Devon’s dividends paid for the first quarter of 2026 and 2025, respectively.
|
|
|
|
|
|
|
|
|
|
|
Dividends |
|
|
Rate Per Share |
|
2026: |
|
|
|
|
|
|
First quarter |
|
$ |
155 |
|
|
$ |
0.24 |
|
2025: |
|
|
|
|
|
|
First quarter |
|
$ |
163 |
|
|
$ |
0.24 |
|
Noncontrolling Interests
On August 1, 2025, Devon completed the acquisition of all outstanding noncontrolling interests in CDM for $260 million. As a result of this transaction, Devon owns 100% of the equity interests in CDM. For additional information, see Note 1.
17.Commitments and Contingencies
Devon is party to various legal actions arising in connection with its business. Matters that are probable of unfavorable outcome to Devon and which can be reasonably estimated are accrued. Such accruals are based on information known about the matters, Devon’s estimates of the outcomes of such matters and its experience in contesting, litigating and settling similar matters. None of the actions are believed by management to likely involve future amounts that would be material to Devon’s financial position or results of operations after consideration of recorded accruals. Actual amounts could differ materially from management’s estimates.
Royalty Matters
Numerous oil and natural gas producers and related parties, including Devon, have been named in various lawsuits alleging royalty underpayments. Devon is currently named as a defendant in a number of such lawsuits, including some lawsuits in which the plaintiffs seek to certify classes of similarly situated plaintiffs. Among the allegations typically asserted in these suits are claims that Devon used below-market prices, made improper deductions, paid royalty proceeds in an untimely manner without including required interest, used improper measurement techniques and entered into gas purchase and processing arrangements with affiliates that resulted in underpayment of royalties in connection with oil, natural gas and NGLs produced and sold. Devon is also involved in governmental agency proceedings and royalty audits and is subject to related contracts and regulatory controls in the ordinary course of business, some that may lead to additional royalty claims. As of March 31, 2026, Devon has accrued approximately $60 million in other current liabilities pertaining to such royalty matters.
Environmental and Climate Change Matters
Devon’s business is subject to numerous federal, state, tribal and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal fines and penalties, as well as remediation costs. Although Devon believes that it is in substantial compliance with applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on its business, there can be no assurance that this will continue in the future.
The Company has previously received separate NOVs from the EPA alleging emissions and permitting violations relating to certain of our historic operations in North Dakota, western Texas and New Mexico, respectively. The Company has been engaging with the EPA to resolve each of these matters, and Devon is actively negotiating a draft consent decree with the EPA and the Department of Justice with respect to the North Dakota NOV matter. If finalized, the consent decree may include monetary sanctions and obligations to complete mitigation projects and implement specific injunctive relief. Given that negotiations of the draft consent decree are ongoing and the uncertainty as to the ultimate result of the North Dakota NOV matter, we are currently unable to provide an estimate of potential loss; however, the costs associated with the resolution of the North Dakota NOV matter or any of the other NOV matters could be significant in amount and may include monetary penalties.
Beginning in 2013, various parishes in Louisiana filed suit against numerous oil and gas companies, including Devon, alleging that the companies’ operations and activities in certain fields violated the State and Local Coastal Resource Management Act of 1978, as amended, and caused substantial environmental contamination, subsidence and other environmental damages to land and water bodies located in the coastal zone of Louisiana. The plaintiffs’ claims against Devon relate primarily to the operations of several of
Devon’s corporate predecessors. The plaintiffs seek, among other things, payment of the costs necessary to clear, re-vegetate and otherwise restore the allegedly impacted areas. Although Devon cannot predict the ultimate outcome of these matters, Devon denies the allegations in these lawsuits and intends to vigorously defend against these claims.
The State of Delaware has filed legal proceedings against numerous oil and gas companies, including Devon, seeking relief to abate alleged impacts of climate change. These proceedings include far-reaching claims for monetary damages and injunctive relief. Although Devon cannot predict the ultimate outcome of this matter, Devon denies the allegations asserted in this lawsuit and intends to vigorously defend against these claims.
Other Indemnifications and Legacy Matters
Pursuant to various sale agreements relating to divested businesses and assets, Devon has indemnified various purchasers against liabilities that they may incur with respect to the businesses and assets acquired from Devon. Additionally, federal, state and other laws in areas of former operations may require previous operators (including corporate successors of previous operators) to perform or make payments in certain circumstances where the current operator may no longer be able to satisfy the applicable obligation. Such obligations may include plugging and abandoning wells, removing production facilities, undertaking other restorative actions or performing requirements under surface agreements in existence at the time of disposition. For example, a predecessor entity of a Devon subsidiary previously sold certain private, state and federal oil and gas leases covering properties in shallow waters off the coast of Louisiana in the Gulf of America. These assets are generally referred to as the East Bay Field. The current operator of the East Bay Field filed for protection under Chapter 11 of the U.S. Bankruptcy Code and was unable to satisfy the eventual decommissioning obligations associated with the East Bay Field. Other companies in the chain of title of the East Bay Field have also sought bankruptcy protection and will also likely be unable to satisfy the eventual decommissioning obligations associated with the East Bay Field.
In March 2025, Devon received an order from the Department of the Interior, Bureau of Safety and Environmental Enforcement to decommission assets located on certain federal leases in the East Bay Field (the “Federal Assets”). As a result, during the first quarter of 2025, Devon recorded a contingent liability of $125 million within other liabilities in the consolidated balance sheet, reflecting the estimated costs of decommissioning the Federal Assets. The Company expects to be able to access funds available under certain bonds and a cash security account as and when Devon performs and pays these decommissioning obligations. Devon believes the funds will likely cover approximately $100 million of the estimated decommissioning costs for the Federal Assets. Accordingly, during the first quarter of 2025, Devon recorded an approximately $100 million receivable related to these sources of funds within other assets in the consolidated balance sheet. The remaining $25 million difference of the recorded decommissioning obligation and such sources of funds was recognized in the first quarter of 2025 in other, net on the consolidated statement of comprehensive earnings. Devon may also be required to perform or fund decommissioning obligations associated with the East Bay Field under state and federal regulations applicable to predecessor operators beyond amounts accrued. Factors impacting this contingency include, among others: (i) the ultimate outcome of the ongoing bankruptcy proceedings, including with respect to state lease assets included in the East Bay Field, (ii) the actual costs to decommission the Federal Assets relative to the estimates, which are subject to numerous assumptions and uncertainties, and (iii) Devon's ability to successfully access funds under decommissioning bonds and other sources.
As of March 31, 2026, Devon has accrued approximately $175 million of contingent liabilities related to such decommissioning legacy matters, including liabilities associated with the East Bay Field.
18.Fair Value Measurements
The following table provides carrying value and fair value measurement information for certain of Devon’s financial assets and liabilities. The carrying values of cash, accounts receivable, other current receivables, accounts payable, other current payables, accrued expenses and lease liabilities included in the accompanying consolidated balance sheets approximated fair value at March 31, 2026 and December 31, 2025, as applicable. Therefore, such financial assets and liabilities are not presented in the following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using: |
|
|
|
Carrying |
|
|
Total Fair |
|
|
Level 1 |
|
|
Level 2 |
|
|
Level 3 |
|
|
|
Amount |
|
|
Value |
|
|
Inputs |
|
|
Inputs |
|
|
Inputs |
|
March 31, 2026 assets (liabilities): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash equivalents |
|
$ |
1,021 |
|
|
$ |
1,021 |
|
|
$ |
1,021 |
|
|
$ |
— |
|
|
$ |
— |
|
Commodity derivatives |
|
$ |
126 |
|
|
$ |
126 |
|
|
$ |
— |
|
|
$ |
126 |
|
|
$ |
— |
|
Commodity derivatives |
|
$ |
(577 |
) |
|
$ |
(577 |
) |
|
$ |
— |
|
|
$ |
(577 |
) |
|
$ |
— |
|
Debt |
|
$ |
(8,386 |
) |
|
$ |
(8,292 |
) |
|
$ |
— |
|
|
$ |
(8,292 |
) |
|
$ |
— |
|
December 31, 2025 assets (liabilities): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash equivalents |
|
$ |
764 |
|
|
$ |
764 |
|
|
$ |
764 |
|
|
$ |
— |
|
|
$ |
— |
|
Commodity derivatives |
|
$ |
194 |
|
|
$ |
194 |
|
|
$ |
— |
|
|
$ |
194 |
|
|
$ |
— |
|
Commodity derivatives |
|
$ |
(1 |
) |
|
$ |
(1 |
) |
|
$ |
— |
|
|
$ |
(1 |
) |
|
$ |
— |
|
Debt |
|
$ |
(8,389 |
) |
|
$ |
(8,290 |
) |
|
$ |
— |
|
|
$ |
(8,290 |
) |
|
$ |
— |
|
The following methods and assumptions were used to estimate the fair values in the table above.
Level 1 Fair Value Measurements
Cash equivalents – Amounts consist primarily of money market investments and the fair value approximates the carrying value.
Level 2 Fair Value Measurements
Commodity derivatives – The fair value of commodity derivatives is estimated using internal discounted cash flow calculations based upon forward curves and data obtained from independent third parties for contracts with similar terms or data obtained from counterparties to the agreements.
Debt – Devon’s debt instruments do not consistently trade actively in an established market. The fair values of our debt are estimated based on rates available for debt with similar terms and maturity when active trading is not available. Our variable rate debt is non-public and consists of our Term Loan. The fair value of our variable rate debt approximates the carrying value as the underlying SOFR resets every month based on the prevailing market rate.
Level 3 Fair Value Measurements
Devon had no fair value measurements using Level 3 inputs at March 31, 2026 or December 31, 2025.
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis addresses material changes in our results of operations for the three-month period ended March 31, 2026 compared to previous periods, and in our financial condition and liquidity since December 31, 2025. For information regarding our critical accounting policies and estimates, see our 2025 Annual Report on Form 10-K under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Executive Overview
We are a leading independent oil and natural gas exploration and production company whose operations are focused onshore in the United States. Our operations are currently focused in four core areas: the Delaware Basin, Rockies, Eagle Ford and Anadarko Basin. Our asset base is underpinned by premium acreage in the economic core of the Delaware Basin and our diverse, top-tier resource plays, providing a deep inventory of opportunities for years to come.
On February 1, 2026, we entered into the Merger Agreement, providing for an all-stock merger of equals with Coterra. The Merger will create a leading large-cap shale operator with an asset base anchored by a premier position in the economic core of the Delaware Basin. The Merger is expected to unlock substantial value for shareholders by leveraging enhanced scale to improve margins, increase free cash flow and accelerate cash returns through the capture of $1.0 billion in sustainable annual synergies. As a company, we remain focused on building economic value by executing on our strategic priorities of moderating production growth, emphasizing capital and operational efficiencies, optimizing reinvestment rates to maximize free cash flow, maintaining low leverage, delivering cash returns to our shareholders and pursuing operational excellence. Our recent performance highlights for these priorities include the following items for the first quarter of 2026:
•Oil production totaled 387 MBbls/d, delivering at the top end of guidance.
•As of March 31, 2026, completed approximately 89% of our authorized $5.0 billion share repurchase program with approximately 102 million of our common shares purchased for approximately $4.5 billion, or $43.90 per share since inception of the plan.
•Exited with $4.8 billion of liquidity, including $1.8 billion of cash.
•Generated $1.7 billion of operating cash flow and $6.4 billion for the trailing twelve months.
•Paid dividends of $155 million.
•On track to achieve 100% of our $1.0 billion optimization plan ahead of schedule.
•Earnings attributable to Devon were $120 million, or $0.19 per diluted share.
•Core earnings (Non-GAAP) were $641 million, or $1.04 per diluted share.
Our net earnings and operating cash flow are highly dependent upon oil, gas and NGL prices, which can be volatile due to several varying factors. As shown in the graph below, during the first quarter of 2026, commodity prices have experienced heightened volatility, driven primarily by significant geopolitical events, including conflict in the Middle East and disruptions to global oil supply, along with continued uncertainty in global trade policy and OPEC+ production decisions. As a result, our net earnings were reduced by a $0.6 billion non-cash valuation loss on our commodity derivatives.
Despite the potential negative impacts of higher inflation rates and supply chain disruptions created by these developments, we remain committed to capital discipline and delivering the objectives that underpin our current plan. Our disciplined, returns-driven strategy is designed to adapt to market fluctuations by reducing activity when necessary to maximize free cash flow generation. We will continue to prioritize value creation through moderated capital investment and production growth, particularly with a view of the volatility in commodity prices, supply chain constraints and the economic uncertainty arising from inflation and geopolitical events. Our cash-return objectives remain focused on opportunistic share repurchases, funding our dividends, repaying debt at upcoming maturities and building cash balances. To emphasize our commitment to maximizing free cash flow and creating value for shareholders, we implemented a business optimization plan early in 2025 targeting a $1.0 billion improvement in annual pre-tax cash flow. The plan included actions to achieve more efficient field-level operations and improvements in drilling and completion costs, along with enhanced operating margins and reduced corporate costs. We are on track to achieve the full $1.0 billion target ahead of our original year-end 2026 timeline.
Results of Operations
The following graphs, discussion and analysis are intended to provide an understanding of our results of operations and current financial condition. To facilitate the review, these numbers are being presented before consideration of noncontrolling interests.
Q1 2026 vs. Q4 2025
Our first quarter 2026 and fourth quarter 2025 net earnings were $120 million and $562 million, respectively. The graph below shows the change in net earnings from the fourth quarter of 2025 to the first quarter of 2026. The material changes are further discussed by category on the following pages.
Production Volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2026 |
|
|
% of Total |
|
|
Q4 2025 |
|
|
Change |
|
Oil (MBbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
|
225 |
|
|
|
58 |
% |
|
|
234 |
|
|
|
-4 |
% |
Rockies |
|
|
103 |
|
|
|
27 |
% |
|
|
102 |
|
|
|
1 |
% |
Eagle Ford |
|
|
43 |
|
|
|
11 |
% |
|
|
39 |
|
|
|
10 |
% |
Anadarko Basin |
|
|
12 |
|
|
|
3 |
% |
|
|
12 |
|
|
|
0 |
% |
Other |
|
|
4 |
|
|
|
1 |
% |
|
|
3 |
|
|
N/M |
|
Total |
|
|
387 |
|
|
|
100 |
% |
|
|
390 |
|
|
|
-1 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2026 |
|
|
% of Total |
|
|
Q4 2025 |
|
|
Change |
|
Gas (MMcf/d) |
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
|
831 |
|
|
|
60 |
% |
|
|
848 |
|
|
|
-2 |
% |
Rockies |
|
|
230 |
|
|
|
17 |
% |
|
|
234 |
|
|
|
-2 |
% |
Eagle Ford |
|
|
76 |
|
|
|
6 |
% |
|
|
56 |
|
|
|
35 |
% |
Anadarko Basin |
|
|
235 |
|
|
|
17 |
% |
|
|
246 |
|
|
|
-4 |
% |
Other |
|
|
1 |
|
|
|
0 |
% |
|
|
1 |
|
|
N/M |
|
Total |
|
|
1,373 |
|
|
|
100 |
% |
|
|
1,385 |
|
|
|
-1 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2026 |
|
|
% of Total |
|
|
Q4 2025 |
|
|
Change |
|
NGLs (MBbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
|
137 |
|
|
|
63 |
% |
|
|
146 |
|
|
|
-7 |
% |
Rockies |
|
|
46 |
|
|
|
21 |
% |
|
|
51 |
|
|
|
-10 |
% |
Eagle Ford |
|
|
11 |
|
|
|
5 |
% |
|
|
10 |
|
|
|
12 |
% |
Anadarko Basin |
|
|
24 |
|
|
|
11 |
% |
|
|
24 |
|
|
|
0 |
% |
Other |
|
|
— |
|
|
|
0 |
% |
|
|
— |
|
|
N/M |
|
Total |
|
|
218 |
|
|
|
100 |
% |
|
|
231 |
|
|
|
-6 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2026 |
|
|
% of Total |
|
|
Q4 2025 |
|
|
Change |
|
Combined (MBoe/d) |
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
|
501 |
|
|
|
60 |
% |
|
|
521 |
|
|
|
-4 |
% |
Rockies |
|
|
187 |
|
|
|
23 |
% |
|
|
192 |
|
|
|
-2 |
% |
Eagle Ford |
|
|
66 |
|
|
|
8 |
% |
|
|
57 |
|
|
|
14 |
% |
Anadarko Basin |
|
|
75 |
|
|
|
9 |
% |
|
|
77 |
|
|
|
-2 |
% |
Other |
|
|
4 |
|
|
|
0 |
% |
|
|
4 |
|
|
N/M |
|
Total |
|
|
833 |
|
|
|
100 |
% |
|
|
851 |
|
|
|
-2 |
% |
From the fourth quarter of 2025 to the first quarter of 2026, the change in volumes contributed to a $94 million decrease in earnings. The decrease in volumes was driven by natural declines and winter weather-related downtime, primarily in the Delaware Basin.
Realized Prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2026 |
|
|
Realization |
|
Q4 2025 |
|
|
Change |
|
Oil (per Bbl) |
|
|
|
|
|
|
|
|
|
|
|
WTI index |
|
$ |
72.10 |
|
|
|
|
$ |
59.09 |
|
|
|
22 |
% |
Realized price, unhedged |
|
$ |
69.66 |
|
|
97% |
|
$ |
57.19 |
|
|
|
22 |
% |
Cash settlements |
|
$ |
(1.72 |
) |
|
|
|
$ |
2.47 |
|
|
|
|
Realized price, with hedges |
|
$ |
67.94 |
|
|
94% |
|
$ |
59.66 |
|
|
|
14 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2026 |
|
|
Realization |
|
Q4 2025 |
|
|
Change |
|
Gas (per Mcf) |
|
|
|
|
|
|
|
|
|
|
|
Henry Hub index |
|
$ |
5.05 |
|
|
|
|
$ |
3.55 |
|
|
|
42 |
% |
Realized price, unhedged |
|
$ |
1.66 |
|
|
33% |
|
$ |
1.33 |
|
|
|
25 |
% |
Cash settlements |
|
$ |
0.02 |
|
|
|
|
$ |
0.25 |
|
|
|
|
Realized price, with hedges |
|
$ |
1.68 |
|
|
33% |
|
$ |
1.58 |
|
|
|
6 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2026 |
|
|
Realization |
|
Q4 2025 |
|
|
Change |
|
NGLs (per Bbl) |
|
|
|
|
|
|
|
|
|
|
|
WTI index |
|
$ |
72.10 |
|
|
|
|
$ |
59.09 |
|
|
|
22 |
% |
Realized price, unhedged |
|
$ |
17.80 |
|
|
25% |
|
$ |
16.86 |
|
|
|
6 |
% |
Cash settlements |
|
$ |
— |
|
|
|
|
$ |
0.23 |
|
|
|
|
Realized price, with hedges |
|
$ |
17.80 |
|
|
25% |
|
$ |
17.09 |
|
|
|
4 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2026 |
|
|
Q4 2025 |
|
|
Change |
|
Combined (per Boe) |
|
|
|
|
|
|
|
|
|
Realized price, unhedged |
|
$ |
39.70 |
|
|
$ |
32.92 |
|
|
|
21 |
% |
Cash settlements |
|
$ |
(0.76 |
) |
|
$ |
1.60 |
|
|
|
|
Realized price, with hedges |
|
$ |
38.94 |
|
|
$ |
34.52 |
|
|
|
13 |
% |
From the fourth quarter of 2025 to the first quarter of 2026, realized prices contributed to a $493 million increase in earnings. Unhedged realized oil, gas and NGL prices increased primarily due to higher WTI, Henry Hub and Mont Belvieu index prices.
We currently have approximately 30% and 35% of our remaining anticipated 2026 oil and gas production hedged, respectively.
Hedge Settlements
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2026 |
|
|
Q4 2025 |
|
|
Change |
|
|
|
Q |
|
|
|
|
|
|
|
Oil |
|
$ |
(60 |
) |
|
$ |
89 |
|
|
|
-167 |
% |
Natural gas |
|
|
3 |
|
|
|
31 |
|
|
|
-90 |
% |
NGL |
|
|
— |
|
|
|
5 |
|
|
N/M |
|
Total cash settlements (1) |
|
$ |
(57 |
) |
|
$ |
125 |
|
|
|
-146 |
% |
(1)Included as a component of oil, gas and NGL derivatives on the consolidated statements of comprehensive earnings.
Cash settlements as presented in the tables above represent realized gains or losses related to the instruments described in Note 3 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
Production Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2026 |
|
|
Q4 2025 |
|
|
Change |
|
LOE |
|
$ |
486 |
|
|
$ |
479 |
|
|
|
1 |
% |
Gathering, processing & transportation |
|
|
191 |
|
|
|
195 |
|
|
|
-2 |
% |
Production taxes |
|
|
205 |
|
|
|
172 |
|
|
|
19 |
% |
Property taxes |
|
|
12 |
|
|
|
15 |
|
|
|
-20 |
% |
Total |
|
$ |
894 |
|
|
$ |
861 |
|
|
|
4 |
% |
Per Boe: |
|
|
|
|
|
|
|
|
|
LOE |
|
$ |
6.48 |
|
|
$ |
6.11 |
|
|
|
6 |
% |
Gathering, processing & transportation |
|
$ |
2.54 |
|
|
$ |
2.49 |
|
|
|
2 |
% |
Percent of oil, gas and NGL sales: |
|
|
|
|
|
|
|
|
|
Production taxes |
|
|
6.9 |
% |
|
|
6.7 |
% |
|
|
3 |
% |
Production expenses increased during the first quarter of 2026 primarily due to higher production taxes resulting from an increase in WTI, Henry Hub and Mont Belvieu index prices.
Field-Level Cash Margin
The table below presents the field-level cash margin for each of our operating areas. Field-level cash margin is computed as oil, gas and NGL sales less production expenses and is not a measure defined by GAAP. A reconciliation to the comparable GAAP measures is found in “Non-GAAP Measures” in this Item 2. The changes in production volumes, realized prices and production expenses, shown above, had the following impact on our field-level cash margins by asset.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2026 |
|
|
$ per BOE |
|
|
Q4 2025 |
|
|
$ per BOE |
|
Field-level cash margin (Non-GAAP) |
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
$ |
1,253 |
|
|
$ |
27.77 |
|
|
$ |
1,083 |
|
|
$ |
22.60 |
|
Rockies |
|
|
451 |
|
|
$ |
26.80 |
|
|
|
341 |
|
|
$ |
19.32 |
|
Eagle Ford |
|
|
238 |
|
|
$ |
40.18 |
|
|
|
177 |
|
|
$ |
33.51 |
|
Anadarko Basin |
|
|
129 |
|
|
$ |
19.18 |
|
|
|
106 |
|
|
$ |
15.02 |
|
Other |
|
|
12 |
|
|
N/M |
|
|
|
10 |
|
|
N/M |
|
Total |
|
$ |
2,083 |
|
|
$ |
27.78 |
|
|
$ |
1,717 |
|
|
$ |
21.93 |
|
DD&A
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2026 |
|
|
Q4 2025 |
|
|
Change |
|
Oil and gas per Boe |
|
$ |
11.71 |
|
|
$ |
10.85 |
|
|
|
8 |
% |
|
|
|
|
|
|
|
|
|
|
Oil and gas |
|
$ |
878 |
|
|
$ |
850 |
|
|
|
3 |
% |
Other property and equipment |
|
|
26 |
|
|
|
40 |
|
|
|
-35 |
% |
Total DD&A |
|
$ |
904 |
|
|
$ |
890 |
|
|
|
2 |
% |
DD&A increased in the first quarter of 2026 primarily due to an increase in the oil and gas DD&A rate. The largest contributor to the higher rate was our 2025 drilling and development activity.
G&A
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2026 |
|
|
Q4 2025 |
|
|
Change |
|
G&A per Boe |
|
$ |
1.67 |
|
|
$ |
1.72 |
|
|
|
-3 |
% |
|
|
|
|
|
|
|
|
|
|
Labor and benefits |
|
$ |
64 |
|
|
$ |
70 |
|
|
|
-9 |
% |
Non-labor |
|
|
61 |
|
|
|
65 |
|
|
|
-6 |
% |
Total |
|
$ |
125 |
|
|
$ |
135 |
|
|
|
-7 |
% |
Other Items
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2026 |
|
|
Q4 2025 |
|
|
Change in earnings |
|
Commodity hedge valuation changes (1) |
|
$ |
(644 |
) |
|
$ |
59 |
|
|
$ |
(703 |
) |
Marketing and midstream operations |
|
|
(16 |
) |
|
|
(30 |
) |
|
|
14 |
|
Exploration expenses |
|
|
25 |
|
|
|
5 |
|
|
|
(20 |
) |
Asset dispositions |
|
|
1 |
|
|
|
(1 |
) |
|
|
(2 |
) |
Net financing costs |
|
|
109 |
|
|
|
107 |
|
|
|
(2 |
) |
Restructuring and transaction costs |
|
|
19 |
|
|
|
— |
|
|
|
(19 |
) |
Other, net |
|
|
17 |
|
|
|
(12 |
) |
|
|
(29 |
) |
|
|
|
|
|
|
|
|
$ |
(761 |
) |
(1)Included as a component of oil, gas and NGL derivatives on the consolidated statements of comprehensive earnings.
We recognize fair value changes on our oil, gas and NGL derivative instruments in each reporting period. The changes in fair value resulted from new positions and settlements that occurred during each period, as well as the relationship between contract prices and the associated forward curves. For additional information, see Note 3 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
In the first quarter of 2026, we incurred transaction costs of approximately $19 million, which included various legal, advisory and other consulting costs associated with the Merger.
Income Taxes
|
|
|
|
|
|
|
|
|
|
|
Q1 2026 |
|
|
Q4 2025 |
|
Current expense (benefit) |
|
$ |
(188 |
) |
|
$ |
23 |
|
Deferred expense |
|
|
234 |
|
|
|
162 |
|
Total expense |
|
$ |
46 |
|
|
$ |
185 |
|
Current tax rate |
|
|
-114 |
% |
|
|
3 |
% |
Deferred tax rate |
|
|
142 |
% |
|
|
22 |
% |
Effective income tax rate |
|
|
28 |
% |
|
|
25 |
% |
For discussion on income taxes, see Note 6 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
Q1 2026 vs. Q1 2025
Our first quarter 2026 and first quarter 2025 net earnings were $120 million and $509 million, respectively. The graph below shows the change in net earnings from the first quarter of 2025 to the first quarter of 2026. The material changes are further discussed by category on the following pages.
Production Volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2026 |
|
|
% of Total |
|
|
Q1 2025 |
|
|
Change |
|
Oil (MBbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
|
225 |
|
|
|
58 |
% |
|
|
216 |
|
|
|
4 |
% |
Rockies |
|
|
103 |
|
|
|
27 |
% |
|
|
112 |
|
|
|
-8 |
% |
Eagle Ford |
|
|
43 |
|
|
|
11 |
% |
|
|
45 |
|
|
|
-5 |
% |
Anadarko Basin |
|
|
12 |
|
|
|
3 |
% |
|
|
11 |
|
|
|
5 |
% |
Other |
|
|
4 |
|
|
|
1 |
% |
|
|
4 |
|
|
N/M |
|
Total |
|
|
387 |
|
|
|
100 |
% |
|
|
388 |
|
|
|
0 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2026 |
|
|
% of Total |
|
|
Q1 2025 |
|
|
Change |
|
Gas (MMcf/d) |
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
|
831 |
|
|
|
60 |
% |
|
|
744 |
|
|
|
12 |
% |
Rockies |
|
|
230 |
|
|
|
17 |
% |
|
|
233 |
|
|
|
-1 |
% |
Eagle Ford |
|
|
76 |
|
|
|
6 |
% |
|
|
117 |
|
|
|
-35 |
% |
Anadarko Basin |
|
|
235 |
|
|
|
17 |
% |
|
|
252 |
|
|
|
-6 |
% |
Other |
|
|
1 |
|
|
|
0 |
% |
|
|
— |
|
|
N/M |
|
Total |
|
|
1,373 |
|
|
|
100 |
% |
|
|
1,346 |
|
|
|
2 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2026 |
|
|
% of Total |
|
|
Q1 2025 |
|
|
Change |
|
NGLs (MBbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
|
137 |
|
|
|
63 |
% |
|
|
118 |
|
|
|
16 |
% |
Rockies |
|
|
46 |
|
|
|
21 |
% |
|
|
44 |
|
|
|
3 |
% |
Eagle Ford |
|
|
11 |
|
|
|
5 |
% |
|
|
15 |
|
|
|
-29 |
% |
Anadarko Basin |
|
|
24 |
|
|
|
11 |
% |
|
|
26 |
|
|
|
-8 |
% |
Other |
|
|
— |
|
|
|
0 |
% |
|
|
— |
|
|
N/M |
|
Total |
|
|
218 |
|
|
|
100 |
% |
|
|
203 |
|
|
|
7 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2026 |
|
|
% of Total |
|
|
Q1 2025 |
|
|
Change |
|
Combined (MBoe/d) |
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
|
501 |
|
|
|
60 |
% |
|
|
458 |
|
|
|
9 |
% |
Rockies |
|
|
187 |
|
|
|
23 |
% |
|
|
195 |
|
|
|
-4 |
% |
Eagle Ford |
|
|
66 |
|
|
|
8 |
% |
|
|
79 |
|
|
|
-17 |
% |
Anadarko Basin |
|
|
75 |
|
|
|
9 |
% |
|
|
79 |
|
|
|
-5 |
% |
Other |
|
|
4 |
|
|
|
0 |
% |
|
|
4 |
|
|
N/M |
|
Total |
|
|
833 |
|
|
|
100 |
% |
|
|
815 |
|
|
|
2 |
% |
From the first quarter of 2025 to the first quarter of 2026, the change in volumes contributed to a $26 million increase in earnings. Volumes increased primarily due to new well activity in the Delaware Basin.
Realized Prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2026 |
|
|
Realization |
|
Q1 2025 |
|
|
Change |
|
Oil (per Bbl) |
|
|
|
|
|
|
|
|
|
|
|
WTI index |
|
$ |
72.10 |
|
|
|
|
$ |
71.50 |
|
|
|
1 |
% |
Realized price, unhedged |
|
$ |
69.66 |
|
|
97% |
|
$ |
69.13 |
|
|
|
1 |
% |
Cash settlements |
|
$ |
(1.72 |
) |
|
|
|
$ |
0.02 |
|
|
|
|
Realized price, with hedges |
|
$ |
67.94 |
|
|
94% |
|
$ |
69.15 |
|
|
|
-2 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2026 |
|
|
Realization |
|
Q1 2025 |
|
|
Change |
|
Gas (per Mcf) |
|
|
|
|
|
|
|
|
|
|
|
Henry Hub index |
|
$ |
5.05 |
|
|
|
|
$ |
3.65 |
|
|
|
38 |
% |
Realized price, unhedged |
|
$ |
1.66 |
|
|
33% |
|
$ |
2.55 |
|
|
|
-35 |
% |
Cash settlements |
|
$ |
0.02 |
|
|
|
|
$ |
(0.07 |
) |
|
|
|
Realized price, with hedges |
|
$ |
1.68 |
|
|
33% |
|
$ |
2.48 |
|
|
|
-32 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2026 |
|
|
Realization |
|
Q1 2025 |
|
|
Change |
|
NGLs (per Bbl) |
|
|
|
|
|
|
|
|
|
|
|
WTI index |
|
$ |
72.10 |
|
|
|
|
$ |
71.50 |
|
|
|
1 |
% |
Realized price, unhedged |
|
$ |
17.80 |
|
|
25% |
|
$ |
22.03 |
|
|
|
-19 |
% |
Cash settlements |
|
$ |
— |
|
|
|
|
$ |
(0.10 |
) |
|
|
|
Realized price, with hedges |
|
$ |
17.80 |
|
|
25% |
|
$ |
21.93 |
|
|
|
-19 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2026 |
|
|
Q1 2025 |
|
|
Change |
|
Combined (per Boe) |
|
|
|
|
|
|
|
|
|
Realized price, unhedged |
|
$ |
39.70 |
|
|
$ |
42.58 |
|
|
|
-7 |
% |
Cash settlements |
|
$ |
(0.76 |
) |
|
$ |
(0.13 |
) |
|
|
|
Realized price, with hedges |
|
$ |
38.94 |
|
|
$ |
42.45 |
|
|
|
-8 |
% |
From the first quarter of 2025 to the first quarter of 2026, realized prices contributed to a $175 million decrease in earnings. This decrease was primarily due to lower unhedged realized gas and NGL prices. This decrease was partially offset by an increase in unhedged realized oil prices. Realized prices were also negatively impacted by oil hedge cash settlements.
Hedge Settlements
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2026 |
|
|
Q1 2025 |
|
|
Change |
|
Oil |
|
$ |
(60 |
) |
|
$ |
— |
|
|
N/M |
|
Natural gas |
|
|
3 |
|
|
|
(8 |
) |
|
|
138 |
% |
NGL |
|
|
— |
|
|
|
(2 |
) |
|
N/M |
|
Total cash settlements (1) |
|
$ |
(57 |
) |
|
$ |
(10 |
) |
|
|
-470 |
% |
(1)Included as a component of oil, gas and NGL derivatives on the consolidated statements of comprehensive earnings.
Cash settlements as presented in the tables above represent realized gains or losses related to the instruments described in Note 3 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
Production Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2026 |
|
|
Q1 2025 |
|
|
Change |
|
LOE |
|
$ |
486 |
|
|
$ |
479 |
|
|
|
1 |
% |
Gathering, processing & transportation |
|
|
191 |
|
|
|
204 |
|
|
|
-6 |
% |
Production taxes |
|
|
205 |
|
|
|
212 |
|
|
|
-3 |
% |
Property taxes |
|
|
12 |
|
|
|
17 |
|
|
|
-29 |
% |
Total |
|
$ |
894 |
|
|
$ |
912 |
|
|
|
-2 |
% |
Per Boe: |
|
|
|
|
|
|
|
|
|
LOE |
|
$ |
6.48 |
|
|
$ |
6.53 |
|
|
|
0 |
% |
Gathering, processing & transportation |
|
$ |
2.54 |
|
|
$ |
2.78 |
|
|
|
-9 |
% |
Percent of oil, gas and NGL sales: |
|
|
|
|
|
|
|
|
|
Production taxes |
|
|
6.9 |
% |
|
|
6.8 |
% |
|
|
2 |
% |
Field-Level Cash Margin
The table below presents the field-level cash margin for each of our operating areas. Field-level cash margin is computed as oil, gas and NGL sales less production expenses and is not a measure defined by GAAP. A reconciliation to the comparable GAAP measures is found in “Non-GAAP Measures” in this Item 2. The changes in production volumes, realized prices and production expenses, shown above, had the following impact on our field-level cash margins by asset.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2026 |
|
|
$ per BOE |
|
|
Q1 2025 |
|
|
$ per BOE |
|
Field-level cash margin (Non-GAAP) |
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
$ |
1,253 |
|
|
$ |
27.77 |
|
|
$ |
1,283 |
|
|
$ |
31.13 |
|
Rockies |
|
|
451 |
|
|
$ |
26.80 |
|
|
|
509 |
|
|
$ |
29.01 |
|
Eagle Ford |
|
|
238 |
|
|
$ |
40.18 |
|
|
|
270 |
|
|
$ |
37.98 |
|
Anadarko Basin |
|
|
129 |
|
|
$ |
19.18 |
|
|
|
136 |
|
|
$ |
19.13 |
|
Other |
|
|
12 |
|
|
N/M |
|
|
|
16 |
|
|
N/M |
|
Total |
|
$ |
2,083 |
|
|
$ |
27.78 |
|
|
$ |
2,214 |
|
|
$ |
30.16 |
|
DD&A and Asset Impairments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2026 |
|
|
Q1 2025 |
|
|
Change |
|
Oil and gas per Boe |
|
$ |
11.71 |
|
|
$ |
12.07 |
|
|
|
-3 |
% |
|
|
|
|
|
|
|
|
|
|
Oil and gas |
|
$ |
878 |
|
|
$ |
886 |
|
|
|
-1 |
% |
Other property and equipment |
|
|
26 |
|
|
|
26 |
|
|
|
0 |
% |
Total DD&A |
|
$ |
904 |
|
|
$ |
912 |
|
|
|
-1 |
% |
|
|
|
|
|
|
|
|
|
|
Asset impairments |
|
$ |
— |
|
|
$ |
254 |
|
|
N/M |
|
In the first quarter of 2025, Devon rationalized two headquarters-related real estate assets resulting in total asset impairments of $254 million. See Note 5 in "Part I. Financial Information – Item 1. Financial Statements" of this report for further discussion.
G&A
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2026 |
|
|
Q1 2025 |
|
|
Change |
|
G&A per Boe |
|
$ |
1.67 |
|
|
$ |
1.77 |
|
|
|
-6 |
% |
|
|
|
|
|
|
|
|
|
|
Labor and benefits |
|
$ |
64 |
|
|
$ |
70 |
|
|
|
-9 |
% |
Non-labor |
|
|
61 |
|
|
|
60 |
|
|
|
2 |
% |
Total |
|
$ |
125 |
|
|
$ |
130 |
|
|
|
-4 |
% |
Other Items
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1 2026 |
|
|
Q1 2025 |
|
|
Change in earnings |
|
Commodity hedge valuation changes (1) |
|
$ |
(644 |
) |
|
$ |
(88 |
) |
|
$ |
(556 |
) |
Marketing and midstream operations |
|
|
(16 |
) |
|
|
(12 |
) |
|
|
(4 |
) |
Exploration expenses |
|
|
25 |
|
|
|
10 |
|
|
|
(15 |
) |
Asset dispositions |
|
|
1 |
|
|
|
2 |
|
|
|
1 |
|
Net financing costs |
|
|
109 |
|
|
|
123 |
|
|
|
14 |
|
Restructuring and transaction costs |
|
|
19 |
|
|
|
18 |
|
|
|
(1 |
) |
Other, net |
|
|
17 |
|
|
|
9 |
|
|
|
(8 |
) |
|
|
|
|
|
|
|
|
$ |
(569 |
) |
(1)Included as a component of oil, gas and NGL derivatives on the consolidated statements of comprehensive earnings.
We recognize fair value changes on our oil, gas and NGL derivative instruments in each reporting period. The changes in fair value resulted from new positions and settlements that occurred during each period, as well as the relationship between contract prices and the associated forward curves. For additional information, see Note 3 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
Income Taxes
|
|
|
|
|
|
|
|
|
|
|
Q1 2026 |
|
|
Q1 2025 |
|
Current expense |
|
$ |
(188 |
) |
|
$ |
96 |
|
Deferred expense |
|
|
234 |
|
|
|
41 |
|
Total expense |
|
$ |
46 |
|
|
$ |
137 |
|
Current tax rate |
|
|
-114 |
% |
|
|
15 |
% |
Deferred tax rate |
|
|
142 |
% |
|
|
6 |
% |
Effective income tax rate |
|
|
28 |
% |
|
|
21 |
% |
For information on income taxes, see Note 6 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
Capital Resources, Uses and Liquidity
Sources and Uses of Cash
The following table presents the major changes in cash and cash equivalents for the three months ended March 31, 2026 and 2025.
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2026 |
|
|
2025 |
|
Operating cash flow |
|
$ |
1,655 |
|
|
$ |
1,942 |
|
Capital expenditures |
|
|
(839 |
) |
|
|
(934 |
) |
Acquisitions of property and equipment |
|
|
(190 |
) |
|
|
(8 |
) |
Divestitures of property, equipment and investments |
|
|
2 |
|
|
|
133 |
|
Investment activity, net |
|
|
7 |
|
|
|
7 |
|
Repurchases of common stock |
|
|
(69 |
) |
|
|
(301 |
) |
Common stock dividends |
|
|
(155 |
) |
|
|
(163 |
) |
Noncontrolling interest activity, net |
|
|
— |
|
|
|
5 |
|
Repayment of finance leases |
|
|
(3 |
) |
|
|
(274 |
) |
Other |
|
|
(27 |
) |
|
|
(19 |
) |
Net change in cash, cash equivalents and restricted cash |
|
$ |
381 |
|
|
$ |
388 |
|
Cash, cash equivalents and restricted cash at end of period |
|
$ |
1,815 |
|
|
$ |
1,234 |
|
Operating Cash Flow
As presented in the table above, net cash provided by operating activities continued to be a significant source of capital and liquidity. Operating cash flow funded our capital expenditures, and we continued to return value to our shareholders by utilizing cash flow and cash balances for share repurchases and dividends.
Capital Expenditures
The amounts in the table below reflect cash payments for capital expenditures, including cash paid for capital expenditures incurred in prior periods.
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2026 |
|
|
2025 |
|
Delaware Basin |
|
$ |
449 |
|
|
$ |
468 |
|
Rockies |
|
|
223 |
|
|
|
222 |
|
Eagle Ford |
|
|
116 |
|
|
|
151 |
|
Anadarko Basin |
|
|
29 |
|
|
|
45 |
|
Other |
|
|
1 |
|
|
|
1 |
|
Total oil and gas |
|
|
818 |
|
|
|
887 |
|
Midstream |
|
|
16 |
|
|
|
32 |
|
Other |
|
|
5 |
|
|
|
15 |
|
Total capital expenditures |
|
$ |
839 |
|
|
$ |
934 |
|
Capital expenditures consist primarily of amounts related to our oil and gas exploration and development operations, midstream operations and other corporate activities. Our capital investment program is driven by a disciplined allocation process focused on moderating our production growth and maximizing our returns. As such, our capital expenditures for the first three months of 2026 represented approximately 51% of our operating cash flow.
Acquisitions of Property and Equipment
During the first three months of 2026, we completed acquisitions of property primarily related to state and federal land sales in the Delaware Basin.
Divestitures of Property and Equipment
During the first three months of 2025, we generated $133 million in proceeds primarily from the sale of headquarters-related real estate assets as part of our real estate rationalization initiatives. For additional information, see Note 5 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
Investment Activity
During the first three months of 2026 and 2025, we received distributions from our investments of $9 million and $9 million, respectively. We contributed $2 million and $2 million to our investments during the first three months of 2026 and 2025, respectively.
Shareholder Distributions and Stock Activity
We repurchased approximately 1.9 million shares of common stock for $69 million and approximately 8.5 million shares of common stock for $301 million under the share repurchase program authorized by our Board of Directors in the first three months of 2026 and 2025, respectively. For additional information, see Note 16 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
The following table summarizes our common stock dividends during the first quarter of 2026 and 2025.
|
|
|
|
|
|
|
|
|
|
|
Dividends |
|
|
Rate Per Share |
|
2026: |
|
|
|
|
|
|
First quarter |
|
$ |
155 |
|
|
$ |
0.24 |
|
2025: |
|
|
|
|
|
|
First quarter |
|
$ |
163 |
|
|
$ |
0.24 |
|
Noncontrolling Interest Activity, net
On August 1, 2025, Devon completed the acquisition of all outstanding noncontrolling interests in CDM for $260 million. Accordingly, all future net income and cash flows from CDM are fully attributable to Devon and there will be no further distributions to or contributions from noncontrolling interest holders.
During the first three months of 2025, we distributed $9 million to our noncontrolling interests in CDM. During the first three months of 2025, we received $14 million in contributions from our noncontrolling interests.
Repayment of Finance Lease
During the first three months of 2025, we paid $274 million in cash to extinguish a finance lease related to a headquarters-related real estate asset as part of our real estate rationalization initiatives. For additional information, see Note 14 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
Liquidity
The business of exploring for, developing and producing oil and natural gas is capital intensive. Because oil, natural gas and NGL reserves are a depleting resource, we, like all upstream operators, must continually make capital investments to grow and even sustain production. Generally, our capital investments are focused on drilling and completing new wells and maintaining production from existing wells. At opportunistic times, we also acquire operations and properties from other operators or landowners to enhance our existing portfolio of assets.
To emphasize our commitment to maximizing free cash flow and creating value for shareholders, we implemented a business optimization plan targeting a $1.0 billion improvement in annual pre-tax cash flow. The optimization initiatives were primarily focused on capital efficiencies, production optimization, commercial opportunities and corporate cost reductions. We are on track to achieve 100% of our $1.0 billion optimization plan ahead of our original year-end 2026 timeline.
Historically, our primary sources of capital funding and liquidity have been our operating cash flow and cash on hand. Additionally, we maintain a commercial paper program, supported by our revolving line of credit, which can be accessed as needed to supplement operating cash flow and cash balances. If needed, we can also issue debt and equity securities, including through transactions under our shelf registration statement filed with the SEC. We estimate the combination of our sources of capital will continue to be adequate to fund our planned capital requirements, as discussed in this section, as well as execute our cash-return business model.
Strategic Merger of Equals
On February 1, 2026, Devon and Coterra entered into the Merger Agreement to combine in an all-stock merger of equals transaction expected to close on May 7, 2026. The strategic combination is expected to unlock substantial value for shareholders by leveraging enhanced scale to improve margins, increase free cash flow and accelerate cash returns through the capture of $1.0 billion in sustainable annual synergies. Following the Merger and subject to the approval of the board of directors of the combined company, we expect to enhance cash returns to shareholders through a planned quarterly dividend of $0.315 per share and a new share repurchase authorization exceeding $5 billion.
Operating Cash Flow
Key inputs into determining our planned capital investment are the amount of cash we hold and operating cash flow we expect to generate over the next one to three or more years. At the end of the first quarter of 2026, we held approximately $1.8 billion of cash. Our operating cash flow forecasts are sensitive to many variables and include a measure of uncertainty as actual results may differ from our expectations.
Commodity Prices – The most uncertain and volatile variables for our operating cash flow are the prices of the oil, gas and NGLs we produce and sell. Prices are determined primarily by prevailing market conditions. Regional and worldwide economic uncertainty arising from geopolitical events, including conflict in the Middle East and related disruptions to global oil supply, weather, changes in public policy and other highly variable factors influence market conditions for these products. These factors, which are difficult to predict, create volatility in prices and are beyond our control.
To mitigate some of the risk inherent in prices, we utilize various derivative financial instruments to protect a portion of our production against downside price risk. The key terms to our oil, gas and NGL derivative financial instruments as of March 31, 2026 are presented in Note 3 in “Part I. Financial Information – Item 1. Financial Statements” of this report.
Further, when considering the current commodity price environment and our current hedge position, we expect to achieve our capital investment priorities. We remain committed to capital discipline and focused on delivering the objectives that underpin our capital plan for 2026.
Operating Expenses – Commodity prices can also affect our operating cash flow through an indirect effect on operating expenses. Significant commodity price decreases can lead to a decrease in drilling and development activities. As a result, the demand and cost for people, services, equipment and materials may also decrease, causing a positive impact on our cash flow as the prices paid for services and equipment decline. However, the inverse is also generally true during periods of rising commodity prices.
Additionally, the economic uncertainty arising from geopolitical events, including conflict in the Middle East and related disruptions to global oil supply, as well as evolving U.S. trade policies and tariff actions, may contribute to higher inflation rates and disrupt supply chains, negatively impacting our cash flow. While we actively work to mitigate the impact of these potential risks
through operational efficiencies gained from the scale of our operations, as well as by leveraging long-standing relationships with our suppliers, the ultimate impacts remain uncertain.
Credit Losses – Our operating cash flow is also exposed to credit risk in a variety of ways. This includes the credit risk related to customers who purchase our oil, gas and NGL production, the collection of receivables from our joint interest owners for their proportionate share of expenditures made on projects we operate and counterparties to our derivative financial contracts. We utilize a variety of mechanisms to limit our exposure to the credit risks of our customers, joint interest owners and counterparties. Such mechanisms include, under certain conditions, requiring letters of credit, prepayments or cash collateral postings.
Credit Availability
As of March 31, 2026, we had approximately $3.0 billion of available borrowing capacity under our Senior Credit Facility. This credit facility supports our $3.0 billion of short-term credit under our commercial paper program. At March 31, 2026, there were no borrowings under our commercial paper program, and we were in compliance with the Senior Credit Facility’s financial covenant.
Debt Ratings
We receive debt ratings from the major ratings agencies in the U.S. In determining our debt ratings, the agencies consider a number of qualitative and quantitative items including, but not limited to, commodity pricing levels, our liquidity, asset quality, reserve mix, debt levels, cost structure, planned asset sales and the size and scale of our production. Our credit rating from Standard and Poor’s Financial Services is BBB with a positive outlook. Our credit rating from Fitch is BBB+ with a positive outlook. Our credit rating from Moody’s Investor Service is Baa2 with a positive outlook. Any rating downgrades may result in additional letters of credit or cash collateral being posted under certain contractual arrangements.
There are no “rating triggers” in any of our contractual debt obligations that would accelerate scheduled maturities should our debt rating fall below a specified level. However, a downgrade could adversely impact our interest rate on our Term Loan or any credit facility borrowings and the ability to economically access debt markets in the future.
Cash Returns to Shareholders
We are committed to returning cash to shareholders through dividends and share repurchases. Our Board of Directors will consider a number of factors when setting the quarterly dividend, if any, including a general target of paying out approximately 10% of operating cash flow through the fixed dividend. In addition to the fixed quarterly dividend, we may pay a variable dividend or complete share repurchases. The declaration and payment of any future dividend, whether fixed or variable, will remain at the full discretion of our Board of Directors and will depend on our financial results, cash requirements, future prospects and other factors deemed relevant by the Board.
Our Board of Directors has authorized a $5.0 billion share repurchase program that expires on June 30, 2026. Through April 2026, we had executed $4.5 billion of the authorized program. Pursuant to the terms of the Merger Agreement, our share repurchase activity has been suspended and is expected to remain suspended through the completion of the Merger.
Capital Expenditures
Our capital expenditures budget for the remainder of 2026 is expected to be consistent with our current operating plans, exclusive of merger-related impacts. Our capital expenditures budget reflecting the combined company will be finalized and communicated following the close of the Merger.
Tax Contingencies
As we are regularly audited by tax authorities, we have and will continue to have our tax positions challenged. Certain tax authorities require material cash deposits be made to further dispute and respond to any of our challenged tax positions. The Canada Revenue Agency (“CRA”) proposed several material adjustments to prior tax years relating to our legacy Canadian business. We have been engaging with the CRA to resolve these matters, but, based on recent communications, we expect the CRA to make formal assessments for such adjustments. We disagree with the proposed adjustments and intend to vigorously contest any related assessments, which may require us to make material cash deposits while the matters are being resolved.
Critical Accounting Estimates
Income Taxes
The amount of income taxes recorded requires interpretations of complex rules and regulations of federal, state, provincial and foreign tax jurisdictions. We recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and other tax carryforwards. We routinely assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or all of the deferred tax assets will not be realized.
On July 4, 2025, OBBB was signed into law. In addition to other provisions, OBBB includes permanent reinstatement of 100% bonus depreciation and the expensing of domestic research costs beginning in 2025 and allows for deduction of intangible drilling costs as part of the computation of the CAMT beginning in 2026. On February 18, 2026, the IRS issued additional interim CAMT guidance through Notice 2026-7. In addition to other provisions, the Notice includes a new AFSI adjustment beginning in 2025 for amortization of domestic research costs, including accelerated amortization under the OBBB transition rule, the impact of which was recorded in the first quarter of 2026. We continue to monitor for additional OBBB guidance.
Further, in the event we were to undergo an “ownership change” (as defined in Section 382 of the Internal Revenue Code of 1986, as amended), our ability to use net operating losses and tax credits generated prior to the ownership change may be limited. Generally, an “ownership change” occurs if one or more shareholders, each of whom owns five percent or more in value of a corporation’s stock, increase their aggregate percentage ownership by more than 50 percent over the lowest percentage of stock owned by those shareholders at any time during the preceding three-year period. Based on currently available information, we do not believe an ownership change has occurred during first quarter 2026 for Devon.
For additional information regarding our critical accounting policies and estimates, see our 2025 Annual Report on Form 10-K.
Non-GAAP Measures
We utilize “core earnings attributable to Devon” and “core earnings per share attributable to Devon” that are not required by or presented in accordance with GAAP. These non-GAAP measures are not alternatives to GAAP measures and should not be considered in isolation or as a substitute for analysis of our results reported under GAAP. Core earnings attributable to Devon, as well as the per share amount, represent net earnings excluding certain non-cash and other items that are typically excluded by securities analysts in their published estimates of our financial results. Our non-GAAP measures are typically used as a quarterly performance measure. Amounts excluded relate to asset dispositions, non-cash asset impairments (including unproved asset impairments), fair value changes in derivative financial instruments and restructuring and transaction costs.
We believe these non-GAAP measures facilitate comparisons of our performance to earnings estimates published by securities analysts. We also believe these non-GAAP measures can facilitate comparisons of our performance between periods and to the performance of our peers.
Below are reconciliations of core earnings and core earnings per share attributable to Devon to comparable GAAP measures.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
Before Tax |
|
|
After Tax |
|
|
After NCI |
|
|
Per Diluted Share |
|
2026: |
|
|
|
|
|
|
|
|
|
|
|
Earnings attributable to Devon (GAAP) |
$ |
166 |
|
|
$ |
120 |
|
|
$ |
120 |
|
|
$ |
0.19 |
|
Adjustments: |
|
|
|
|
|
|
|
|
|
|
|
Asset dispositions |
|
1 |
|
|
|
1 |
|
|
|
1 |
|
|
|
— |
|
Asset and exploration impairments |
|
2 |
|
|
|
2 |
|
|
|
2 |
|
|
|
0.01 |
|
Fair value changes in financial instruments |
|
644 |
|
|
|
499 |
|
|
|
499 |
|
|
|
0.81 |
|
Restructuring and transaction costs |
|
19 |
|
|
|
19 |
|
|
|
19 |
|
|
|
0.03 |
|
Core earnings attributable to Devon (Non-GAAP) |
$ |
832 |
|
|
$ |
641 |
|
|
$ |
641 |
|
|
$ |
1.04 |
|
2025: |
|
|
|
|
|
|
|
|
|
|
|
Earnings attributable to Devon (GAAP) |
$ |
646 |
|
|
$ |
509 |
|
|
$ |
494 |
|
|
$ |
0.77 |
|
Adjustments: |
|
|
|
|
|
|
|
|
|
|
|
Asset dispositions |
|
2 |
|
|
|
1 |
|
|
|
1 |
|
|
|
— |
|
Asset and exploration impairments |
|
259 |
|
|
|
202 |
|
|
|
202 |
|
|
|
0.31 |
|
Fair value changes in financial instruments |
|
88 |
|
|
|
68 |
|
|
|
68 |
|
|
|
0.11 |
|
Restructuring and transaction costs |
|
18 |
|
|
|
14 |
|
|
|
14 |
|
|
|
0.02 |
|
Core earnings attributable to Devon (Non-GAAP) |
$ |
1,013 |
|
|
$ |
794 |
|
|
$ |
779 |
|
|
$ |
1.21 |
|
EBITDAX and Field-Level Cash Margin
To assess the performance of our assets, we use EBITDAX and Field-Level Cash Margin. We compute EBITDAX as net earnings before income tax expense; financing costs, net; exploration expenses; DD&A; asset impairments; asset disposition gains and losses; non-cash share-based compensation; non-cash valuation changes for derivatives and financial instruments; restructuring and transaction costs; accretion on discounted liabilities; and other items not related to our normal operations. Field-Level Cash Margin is computed as oil, gas and NGL sales less production expenses. Production expenses consist of lease operating, gathering, processing and transportation expenses, as well as production and property taxes.
We exclude financing costs from EBITDAX to assess our operating results without regard to our financing methods or capital structure. Exploration expenses and asset disposition gains and losses are excluded from EBITDAX because they generally are not indicators of operating efficiency for a given reporting period. DD&A and impairments are excluded from EBITDAX because capital expenditures are evaluated at the time capital costs are incurred. We exclude share-based compensation, valuation changes, restructuring and transaction costs, accretion on discounted liabilities and other items from EBITDAX because they are not considered a measure of asset operating performance.
We believe EBITDAX and Field-Level Cash Margin provide information useful in assessing our operating and financial performance across periods. EBITDAX and Field-Level Cash Margin as defined by Devon may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with net earnings from operations.
Below are reconciliations of net earnings to EBITDAX and a further reconciliation to Field-Level Cash Margin.
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2026 |
|
|
2025 |
|
Net earnings (GAAP) |
|
$ |
120 |
|
|
$ |
509 |
|
Financing costs, net |
|
|
109 |
|
|
|
123 |
|
Income tax expense |
|
|
46 |
|
|
|
137 |
|
Exploration expenses |
|
|
25 |
|
|
|
10 |
|
Depreciation, depletion and amortization |
|
|
904 |
|
|
|
912 |
|
Asset impairments |
|
|
— |
|
|
|
254 |
|
Asset dispositions |
|
|
1 |
|
|
|
2 |
|
Share-based compensation |
|
|
22 |
|
|
|
24 |
|
Derivative and financial instrument non-cash valuation changes |
|
|
644 |
|
|
|
88 |
|
Restructuring and transaction costs |
|
|
19 |
|
|
|
18 |
|
Accretion on discounted liabilities and other |
|
|
17 |
|
|
|
9 |
|
EBITDAX (Non-GAAP) |
|
|
1,907 |
|
|
|
2,086 |
|
Marketing and midstream revenues and expenses, net |
|
|
16 |
|
|
|
12 |
|
Commodity derivative cash settlements |
|
|
57 |
|
|
|
10 |
|
General and administrative expenses, cash-based |
|
|
103 |
|
|
|
106 |
|
Field-level cash margin (Non-GAAP) |
|
$ |
2,083 |
|
|
$ |
2,214 |
|
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
As of March 31, 2026, we have commodity derivatives that pertain to a portion of our estimated production for the last nine months of 2026, as well as for 2027. The key terms to our open oil, gas and NGL derivative financial instruments are presented in Note 3 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
The fair values of our commodity derivatives are largely determined by the forward curves of the relevant price indices. At March 31, 2026, a 10% change in the forward curves associated with our commodity derivative instruments would have changed our net positions by approximately $300 million.
Interest Rate Risk
At March 31, 2026, we had total debt of $8.4 billion. Of this debt, $7.4 billion was comprised of debentures and notes that have fixed interest rates which averaged 5.7%. We also have a $1.0 billion Term Loan which has a variable interest rate that is adjusted monthly. The interest rate on the Term Loan was 5.2% at March 31, 2026.
Item 4. Controls and Procedures
Disclosure Controls and Procedures
We have established disclosure controls and procedures to ensure that material information relating to Devon, including its consolidated subsidiaries, is made known to the officers who certify Devon’s financial reports and to other members of senior management and the Board of Directors.
Based on their evaluation, our principal executive and principal financial officers have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective as of March 31, 2026 to ensure that the information required to be disclosed by Devon in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms.
Changes in Internal Control Over Financial Reporting
On January 1, 2026, Devon completed the implementation of an upgraded enterprise resource planning software. As a result of this implementation, corresponding changes to our business processes and information systems have been made, updating applicable internal controls over financial reporting where necessary.
Except as described above, there were no other changes in our internal control over financial reporting that occurred during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
